In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a "drill string." The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus turns the bit and advances it downwardly, causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all cutting methods. While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit through flow channels that are formed in the bit. The drilling fluid is provided to cool the bit and to flush cuttings away from the cutting structure of the bit and upwardly into the annulus formed between the drill string and the borehole.
Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Such bits include fixed cutter bits and roller cone bits. The types of cutting structures include milled tooth bits, tungsten carbide insert ("TCI") bits, PDC bits, and natural diamond bits. The selection of the appropriate bit and cutting structure for a given application depends upon many factors. One of the most important of these factors is the type of formation that is to be drilled, and more particularly, the hardness of the formation that will be encountered. Another important consideration is the range of hardnesses that will be encountered when drilling through layers of differing formation hardness.
Depending upon formation hardness, certain combinations of the above-described bit types and cutting structures will work more efficiently and effectively against the formation than others. For example, a milled tooth bit generally drills relatively quickly and effectively in soft formations, such as those typically encountered at shallow depths. By contrast, milled tooth bits are relatively ineffective in hard rock formations as may be encountered at greater depths. For drilling through such hard formations, roller cone bits having TCI cutting structures have proven to be effective. For certain hard formations, fixed cutter bits having a natural diamond cutting structure provide the best combination of penetration rate and durability. In formations of soft and medium hardness, fixed cutter bits having a PDC cutting structure are employed with good results.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed the entire drill string, which may be miles long, must be retrieved from the borehole section by section. After the drill string is retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which again must be constructed section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer and which are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit may be employed before it must be changed depends upon its durability or ability to maintain a high or acceptable rate of penetration ("ROP"). Additionally, a desirable characteristic of the bit is that it be "stable" and resist vibration, the most severe type or mode of which is "whirl," which is a term used to describe the phenomenon where a drill bit rotates at the bottom of the borehole about a rotational axis that is offset from the geometric center of the drill bit. Such whirling subjects the cutting elements on the bit to increased loading, which causes the premature wearing or destruction of the cutting elements and decreased penetration rates.
In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. The cutting elements used in such bits are formed of extremely hard materials and include a layer of polycrystalline diamond material. In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, preformed cutting element having a thin, hard cutting layer of polycrystalline diamond is bonded to the exposed end of the support member, which is typically formed of tungsten carbide.
As PDC bits were being developed for use in harder formations, their cutting structures were, in many instances, designed so as to be "heavy set," which means that the bit was provided with a large number of cutter elements distributed about the face of the bit such that each of the elements would remove a comparatively small amount of material from the formation during each revolution and would be subjected to a loading that was less than the loading that would be experienced by the cutter elements if fewer cutter elements were provided. This arrangement is to be contrasted with a "light set" bit which had proven successful in softer formations and which has comparatively fewer but larger sized cutter elements, each of which would remove a greater volume of formation material than the elements used in a "heavy set" bit.
Because of the difference in design and construction of the heavy set and light set PDC bits, inefficiencies resulted when using one of these bit designs to drill through formations of differing hardness. For example, if a heavy set bit was used for the reason that a lower formation layer had a relatively high degree of hardness compared to a softer upper layer, the heavy set bit tended to clog in the softer formations, resulting in a reduced ROP in that section of the borehole. Alternatively, if a light set bit was used, the ROP in the hard formation was relatively slow in comparison to the rate that could be achieved using a heavy set bit. Thus, where PDC bits were to be used, it was frequently necessary to accept lower ROP's while drilling through formations of one degree of hardness or another, or to trip the drill string and change the drill bits when drilling through formations of differing hardness. Either of these alternatives could be extremely costly.
A common arrangement of the PDC cutting elements was at one time to place them in a spiral configuration. More specifically, the cutter elements were placed at selected radial positions with respect to the central axis of the bit, with each element being placed at a more remote radial position than the preceding element. So positioned, the path of all but the center-most elements partly overlapped the path of movement of a preceding cutter element as the bit was rotated. Thus, each element would remove a lesser volume of material than would be the case if it were radially positioned so that no overlapping occurred, or occurred to a lesser extent, because the leading cutter element would already have removed some formation material from the path traveled by the following cutter element. Using this arrangement, each cutter tended to remove a comparatively small amount of material from the formation during each revolution, and was subjected to substantially the same loading as the other cutter elements on the bit face.
Although the spiral arrangement was once widely employed, this arrangement of cutter elements was found to wear in a manner to cause the bit to assume a cutting profile presenting a relatively flat and single continuous cutting edge from one element to the next. Not only did this decrease the ROP that the bit could provide, it but also increased the likelihood of bit vibration. Both of these conditions are undesirable. A low ROP increases drilling time and cost and may necessitate a costly trip of the drill string in order to replace the dull bit with a new bit. Excessive bit vibration will itself dull or damage the bit to the extent that a premature trip of the drill string becomes necessary.
Thus, in addition to providing a bit capable of drilling effectively at desirable ROP's through a variety of formation hardnesses, preventing bit vibration and maintaining stability of PDC bits has long been a desirable goal, but one which has not always been achieved. Bit vibration typically may occur in any type of formation, but is most detrimental in the harder formations. As described above, the cutter elements in many prior art PDC bits were positioned in a spiral relationship which, as drilling progressed, wore in a manner which caused the ROP to decrease and which also increased the likelihood of bit vibration.
There have been a number of designs proposed for PDC cutting structures that are meant to provide a PDC bit capable of drilling through a variety of formation hardnesses at effective ROP's and with acceptable bit life or durability. For example, U.S. Pat. No. 5,033,560 (Sawyer et al.) describes a PDC bit having mixed sizes of PDC cutter elements with larger cutter elements positioned near the central axis of the bit and cutters of decreasing diameter at positions more distant from the central axis. This arrangement was intended to provide improved ROP while maintaining bit durability, but because the bit tends to wear in a pattern producing a relatively smooth cutting profile, the bit tends to be unstable, particularly in hard rock formations. Similarly, U.S. Pat. No. 5,222,566 (Taylor et at.) describes a drill bit which employs PDC cutter elements of differing sizes, with the larger size elements employed in a first group of cutters disposed on a first blade and smaller size cutters employed in a second group on a second blade. This bit also presents a relatively smooth cutting profile to the formation which limits the bit's ability to resist vibration. This design also suffers from the fact that the bit blades do not share the cutting load equally. Instead, the blade on which the larger sized cutters are mounted is loaded to a greater degree than the blade with the smaller cutter elements. This could lead to blade failure. U.S. Pat. No. Re. 33,757 (Weaver) describes a bit with an arrangement of blunt and scribe shaped cutters wherein the scribe cutters located directly before and between blunt cutting elements. The scribe cutters are intended to prefracture formation material and leave a series of kerfs. Following the scribe cutters are a series of blunt cutters intended to dislodge formation from between the kerfs. While this design was intended to enhance drilling performance in formations classified as medium-soft to medium, this bit includes no features directed toward stabilizing the bit once wear has commenced. Further, the bit's cutting structure has been found to limit the bit's application to relatively brittle formations.
Separately, other attempts have been made to design bits that will minimize or prevent bit vibration. For example, U.S. Pat. No. Re. 34,435 (Warren et al.) describes a bit having a set of cutters which are disposed at an equal radius from the center of the bit and which extend further from the bit face than the other cutters on the bit. According to Warren, the set of cutters extending furthest from the bit face are provided so as to cut a circular groove within the formation. In this design, the extending cutters are meant to ride in the groove in order to stabilize the bit. Similarly, U.S. Pat. No. 5,265,685 (Keith et al.) discloses a PDC bit that is designed to cut a series of grooves in the formation such that the resulting ridges that are formed between the concentric grooves will tend to stabilize the bit. U.S. Pat. No. 5,238,075 (Keith et at.) describes a PDC bit having a cutter element arrangement intended to provide stabilization which employs cutter elements of different sizes. However, the design taught in the '075 patent discloses mounting the smaller cutter elements such that, in rotated profile, their cutting profiles fall entirely within the cutting profiles of larger elements. This arrangement requires that a relatively large number of large cutter elements be positioned on the bit face. This limits the number of cutter elements that can be mounted on the bit face and, in turn, decreases the total surface area of diamond material available for cutting the formation material.
Additionally, many of these designs aimed at minimizing bit vibration required that drilling be conducted with an increased weight-on-bit (WOB) as compared with bits of earlier designs. Increasing the WOB is accomplished by adding additional heavy drill collars to the drill string in order to provide acceptable penetration rates. However, drilling with an increased or heavy WOB has serious consequences and is avoided whenever possible. The additional weight increases the stress and strain on all drill string components, causes stabilizers to wear more quickly and to work less efficiently, and increases the hydraulic pressure drop in the drill string, requiring the use of higher capacity (and typically higher cost) pumps for circulating the drilling fluid.
Thus, despite attempts and certain advances made in the art, there remains a need for a PDC bit having an improved cutter arrangement which will permit the bit to drill effectively at economical ROP's, and that will provide an increased measure of stability, both initially and as wear occurs. More specifically, there is a need for a PDC bit which can drill in soft, medium, medium hard and even in some hard formations while maintaining an aggressive cutter profile so as to maintain good ROP's for acceptable lengths of time and thereby lower the drilling costs presently experienced in the industry. Ideally, such a bit would provide an increased measure of stability so as to resist bit vibration without having to employ substantial additional WOB.